Viscoelastic surfactant fluids and associated methods

ABSTRACT

Provided are treatment fluids that comprise an aqueous based fluid, a water-soluble salt, and a methyl ester sulfonate surfactant, and associated methods. In one embodiment, a method of treating a subterranean formation is provided, the method comprising: providing a treatment fluid comprising an aqueous base fluid, a water-soluble salt, and a methyl ester sulfonate surfactant; and introducing the treatment fluid into a well bore that penetrates the subterranean formation. Also provided are methods of fracturing a subterranean formation, and methods of removing formation particulates from a well bore or a near well bore region. In some instances, the treatment fluids exhibit viscoelastic behavior which may be due, at least in part, to the association of at least a portion of the methyl ester sulfonate surfactant into a plurality of micellar structures.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present invention is related to co-pending U.S. application Ser. No.______ [Attorney Docket No. HES 2004-IP-013785U2] entitled “ViscoelasticSurfactant Fluids and Associated Acidizing Methods,” filed concurrentlyherewith, co-pending U.S. application Ser. No. ______ [Attorney DocketNo. HES 2004-IP-013785U3] entitled “Viscoelastic Surfactant Fluids andAssociated Diverting Methods,” filed concurrently herewith, andco-pending U.S. application Ser. No. ______ [Attorney Docket No. HES2004-IP-013785U4] entitled “Viscoelastic Surfactant Fluids andAssociated Methods,” filed concurrently herewith, the entire disclosuresof which are incorporated herein by reference.

BACKGROUND

The present invention relates to methods and compositions for treatingsubterranean formations. More particularly, the present inventionrelates to treatment fluids that comprise a methyl ester sulfonate(“MES”) surfactant, and associated methods.

Viscosified treatment fluids may be used in a variety of subterraneantreatments. Such treatments include, but are not limited to, drillingoperations, stimulation treatments, and sand control treatments. As usedherein, the term “treatment,” or “treating,” refers to any subterraneanoperation that uses a fluid in conjunction with a desired functionand/or for a desired purpose. The term “treatment,” or “treating,” doesnot imply any particular action by the fluid.

Drilling operations typically require the use of a drilling fluid.During drilling operations, a viscosified treatment fluid (e.g., adrilling fluid) passes down through the inside of the drill string,exits through the drill bit, and returns to the drilling rig through theannulus between the drill string and well bore. The circulating drillingfluid, among other things, lubricates the drill bit, transports drillcuttings to the surface, and balances the formation pressure exerted onthe well bore. Drilling fluids typically require sufficient viscosity tosuspend drill cuttings. Viscosified treatment fluids also may be used inother operations to transport and remove formation particulates from thewell bore or the near well bore region. In some instances, theseformation particulates may be generated during the course of drilling,digging, blasting, dredging, tunneling, and the like in the subterraneanformation.

One common production stimulation operation that employs a viscosifiedtreatment fluid is hydraulic fracturing. Hydraulic fracturing operationsgenerally involve pumping a viscosified treatment fluid (e.g., afracturing fluid) into a well bore that penetrates a subterraneanformation at a sufficient hydraulic pressure to create or enhance one ormore cracks, or “fractures,” in the subterranean formation. Thefracturing fluid may comprise particulates, often referred to as“proppant particulates,” that are deposited in the fractures. Theproppant particulates function, inter alia, to prevent the fracturesfrom fully closing upon the release of hydraulic pressure, formingconductive channels through which fluids may flow to the well bore. Onceat least one fracture is created and the proppant particulates aresubstantially in place, the viscosity of the fracturing fluid usually isreduced, and the fracturing fluid may be recovered from the formation.

Treatment fluids are also utilized in sand control treatments, such asgravel packing. In gravel-packing treatments, the viscosified treatmentfluid suspends particulates (commonly referred to as “gravelparticulates”) for delivery to a desired area in a well bore, e.g., nearunconsolidated or weakly consolidated formation zones, to form a gravelpack to enhance sand control. One common type of gravel-packingoperation involves placing a sand control screen in the well bore andpacking the annulus between the screen and the well bore with the gravelparticulates of a specific size designed to prevent the passage offormation sand. The gravel particulates act, inter alia, to prevent theformation particulates from occluding the screen or migrating with theproduced hydrocarbons, and the screen acts, inter alia, to prevent theparticulates from entering the production tubing. Once the gravel packis substantially in place, the viscosity of the treatment fluid is oftenreduced to allow it to be recovered. In some situations, fracturing andgravel-packing treatments are combined into a single treatment (commonlyreferred to as “frac pack” operations) to provide stimulated productionand an annular gravel pack to reduce formation sand production. In somecases, the treatments are completed with a gravel pack screen assemblyin place, and the fracturing treatment fluid being pumped through theannular space between the casing and screen. In such a situation, thefracturing treatment usually ends in a screen-out condition, creating anannular gravel pack between the screen and casing. This allows both thefracturing treatment and gravel pack to be placed in a single operation.

Maintaining sufficient viscosity in these fluids is important for anumber of reasons. Viscosity is desirable in drilling operations sincetreatment fluids with higher viscosity can, among other things,transport solids, such as drill cuttings, more readily. Maintainingsufficient viscosity is important in fracturing treatments forparticulate transport, as well as to create or enhance fracture width.Particulate transport is also important in sand control treatments, suchas gravel packing. Also, maintaining sufficient viscosity may beimportant to control and/or reduce leak-off into the formation. Toprovide the desired viscosity, polymeric gelling agents commonly areadded to the treatment fluids. Examples of commonly used polymericgelling agents include, but are not limited to, guar gums andderivatives thereof, cellulose derivatives, biopolymers, and the like.The use of polymeric gelling agents, however, may be problematic. Forinstance, these polymeric gelling agents may leave an undesirableresidue in the subterranean formation after use. As a result,potentially costly remedial operations may be required to clean up thefracture face and proppant pack. Foamed treatment fluids andemulsion-based treatment fluids have been employed to minimize residualdamage, but increased expense and complexity often result.

To combat these problems associated with polymeric gelling agents, somesurfactants have been used as gelling agents. Certain surfactants, whenmixed with an aqueous fluid having a certain ionic strength, are capableof forming a viscous fluid that has certain elastic properties, one ofwhich may be shear thinning. Surfactant molecules (or ions) at specificconditions may form micelles (e.g., worm-shaped micelles, rod-shapedmicelles, etc.) in an aqueous fluid. Depending on, among other things,the surfactant concentration, and the ionic strength of the fluid, etc.,these micelles may impart increased viscosity to the aqueous fluid, suchthat the fluid exhibits viscoelastic behavior due, at least in part, tothe association of the surfactant molecules contained therein.

As a result, these treatment fluids exhibiting viscoelastic behavior maybe used in a variety of subterranean treatments where a viscosifiedtreatment fluid may be useful. Because the micelles may be sensitive tothe pH and hydrocarbons, the viscosity of these treatment fluids may bereduced after introduction into the subterranean formation without theneed for conventional gel breakers (e.g., oxidizers). This may allow asubstantial portion of the treatment fluid to be produced back from theformation without the need for expensive remedial treatments. However,surfactants used heretofore as gelling agents tend to have undesirableenvironmental characteristics (e.g., toxicity) and/or may be limited bystrict environmental regulations in certain areas of the world.

SUMMARY

The present invention relates to methods and compositions for treatingsubterranean formations. More particularly, the present inventionrelates to treatment fluids that comprise a MES surfactant, andassociated methods.

An embodiment of the present invention provides a method of treating asubterranean formation, the method comprising: providing a treatmentfluid comprising an aqueous base fluid, a water-soluble salt, and a MESsurfactant; and introducing the treatment fluid into a well bore thatpenetrates the subterranean formation.

Another embodiment of the present invention provides a method offracturing a subterranean formation, the method comprising: providing atreatment fluid, the treatment fluid comprising an aqueous base fluid, awater-soluble salt, and a MES surfactant, wherein the treatment fluidexhibits viscoelastic behavior due, at least in part, to the associationof at least a portion of the MES surfactant into a plurality of micellarstructures; and introducing the treatment fluid into a well bore thatpenetrates the subterranean formation at or above a pressure sufficientto create or enhance one or more fractures in a portion of thesubterranean formation.

Another embodiment of the present invention provides a method ofremoving formation particulates from a well bore or a near well boreregion, the method comprising: providing a treatment fluid, thetreatment fluid comprising an aqueous base fluid, a water-soluble salt,and a MES surfactant, wherein the treatment fluid exhibits viscoelasticbehavior due, at least in part, to the association of at least a portionof the MES surfactant into a plurality of micellar structures; andintroducing the treatment fluid into the well bore so as to suspend aplurality of formation particulates in the treatment fluid.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

DRAWINGS

A more complete understanding of the present disclosure and advantagesthereof may be acquired by referring to the following description takenin conjunction with the accompanying drawings, wherein:

FIG. 1 is a plot of temperature versus viscosity as measured using anonscanning shear rate procedure on a Fann Model 50 viscometer forsample fluids that comprises a MES surfactant and concentrations ofsodium chloride.

FIG. 2 is a plot of shear stress versus storage modulus, loss modulus,and phase angle as measured using a Haake Rheostress RS150stress-controlled rheometer for a sample fluid that comprises a MESsurfactant and sodium chloride.

FIG. 3 is a plot of shear stress versus storage modulus, loss modulus,and phase angle as measured using a Haake Rheostress RS150stress-controlled rheometer for another sample fluid that comprises aMES surfactant and sodium chloride.

While the present invention is susceptible to various modifications andalternative forms, specific exemplary embodiments thereof have beenshown by way of example in the drawings and are herein described indetail. It should be understood, however, that the description herein ofspecific embodiments is not intended to limit or define the invention tothe particular forms disclosed, but on the contrary, the intention is tocover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention as defined by the appended claims.The figures should in no way be used to limit the meaning of the claimterms.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to methods and compositions for treatingsubterranean formations. More particularly, the present inventionrelates to treatment fluids that comprise a MES surfactant, andassociated methods.

The treatment fluids of the present invention generally comprise a MESsurfactant, an aqueous base fluid, and a water-soluble salt. In someinstances, the treatment fluids of the present invention may exhibitviscoelastic behavior which may be due, at least in part, to theassociation of at least a portion of the MES surfactant into a pluralityof micellar structures. Additionally, other additives suitable for usein the particular application may be included in the treatment fluids ofthe present invention as recognized by one of ordinary skill in the arthaving the benefit of this disclosure.

The MES surfactants suitable for use in the present invention aredescribed by the following formula:

where R is an alkyl chain of from about 10 carbon atoms to about 30carbon atoms. In some embodiments, R is an alkyl chain of from about 16carbon atoms to about 22 carbon atoms. An example of a suitable MESsurfactant of Formula I is a palm-oil derivative commercially availablefrom Halliburton Energy Services, Inc., Duncan, Okla., under the tradename EFS™-4 surfactant. MES surfactants are believed to be relativelyenvironmentally benign, in most instances, because these surfactants arebiodegradable in most environments. The MES surfactants of Formula I area class of anionic surfactants that have been found to cause fluids toexhibit viscoelastic properties. It is believed that, when the MESsurfactant is dissolved in an aqueous environment having a certain ionicstrength, the MES surfactant molecules (or ions) may associate to formmicelles because of their hydrophobic and hydrophilic regions. Thesemicelles may be rod-shaped, worm-shaped, or any of a variety of othershapes that will viscosify a fluid where present in sufficientconcentrations. These micelles, among other things, may increase theviscosity of the fluid therein. In the presence of a sufficient amountof hydrocarbons or at a certain ionic strength, these micelles maybecome unstable, thereby disassociating or forming a micellar structurethat is not conducive to viscosifying a fluid. This disassociationand/or modification of the micellar structure leads to a reduction inviscosity for the treatment fluid.

The MES surfactant should be present in an embodiment of a treatmentfluid of the present invention in an amount sufficient to provide thedesired viscosity (e.g., sufficient for particulate transport, etc.)therein through formation of the desired micelles. In certainembodiments, the MES surfactant may be present in the fluids in anamount of from about 0.5% to about 15% by weight of the treatment fluid(“bwof”). In certain exemplary embodiments, the MES surfactant may bepresent in the treatment fluids of the present invention in an amount offrom about 0.5% to about 5% bwof. One of ordinary skill in the art, withthe benefit of this disclosure, will be able to determine theappropriate amount of the MES surfactant to include in a treatment fluidof the present invention based on a number of factors, including theamount and type of the one or more salts used, the desired viscosity,the ionic strength of the fluid, and/or the amount and type ofco-surfactant employed.

The aqueous base fluid used in the treatment fluids of the presentinvention may comprise fresh water, saltwater (e.g., water containingone or more salts dissolved therein), brine (e.g., saturated saltwater),seawater, or combinations thereof. Generally, the water may be from anysource, provided that it does not contain components that mightadversely affect the stability of the treatment fluids of the presentinvention.

To provide the ionic strength for the desired micelle formation, thetreatment fluids of the present invention comprise a water-soluble salt.Adding a salt may promote micelle formation for the viscosification ofthe fluid. In some embodiments, the aqueous base fluid may contain thewater-soluble salt, for example, where saltwater, a brine, or seawateris used as the aqueous base fluid. Suitable water-soluble salts maycomprise lithium, ammonium, sodium, potassium, cesium, magnesium,calcium, or zinc cations, and chloride, bromide, iodide, formate,nitrate, acetate, cyanate, or thiocynate anions. Examples of suitablewater-soluble salts that comprise the above-listed anions and cationsinclude, but are not limited to, ammonium chloride, lithium bromide,lithium chloride, lithium formate, lithium nitrate, calcium bromide,calcium chloride, calcium nitrate, calcium formate, sodium bromide,sodium chloride, sodium formate, sodium nitrate, potassium chloride,potassium bromide, potassium nitrate, potassium formate, cesium nitrate,cesium formate, cesium chloride, cesium bromide, magnesium chloride,magnesium bromide, zinc chloride, and zinc bromide. In certainembodiments, the water-soluble salt may be present in the treatmentfluids of the present invention in an amount in the range of from about1% to about 10% bwof. In certain other embodiments, the water-solublesalt may be present in the treatment fluids of the present invention inan amount in the range of from about 5% to about 10% bwof.

The treatment fluids may optionally comprise a co-surfactant, amongother things, to facilitate the formation of and/or stabilize a foam,increase salt tolerability, and/or stabilize the treatment fluid. Theco-surfactant may comprise any surfactant suitable for use insubterranean environments that does not adversely affect the treatmentfluid. Examples of suitable co-surfactants include betaines (e.g.,cocobetaine, cocoamidopropylbetaine), amine oxides, derivatives thereof,and combinations thereof. One of ordinary skill in the art will be ableto determine which co-surfactants are best suited to the particularembodiments and applications of the compositions and methods describedherein. For example, in some embodiments, the treatment fluids may befoamed by injection of a gas therein, wherein a co-surfactant (such as acocobetaine) is included in treatment fluids to facilitate the formationof and/or stabilize the foam. In some embodiments, the co-surfactant mayact to at least partially stabilize the treatment fluid. Generally, theco-surfactants may be present an amount sufficient to optimize theperformance of the treatment fluid in a particular application, asdetermined by one of ordinary skill in the art. In one embodiment, forexample, where the co-surfactant is included to increase salttolerability or to stabilize the treatment fluids of the presentinvention, the co-surfactant is present in a co-surfactant-to-MESsurfactant weight ratio in the range of from about 1:3 to about 3:1.

The treatment fluids of the present invention may further compriseparticulates (such as proppant particulates or gravel particulates)suitable for use in subterranean applications. Particulates suitable foruse in the present invention may comprise any material suitable for usein subterranean operations. Suitable particulate materials include, butare not limited to, sand, bauxite, ceramic materials, glass materials,polymer materials, Teflon® materials, nut shell pieces, cured resinousparticulates comprising nut shell pieces, seed shell pieces, curedresinous particulates comprising seed shell pieces, fruit pit pieces,cured resinous particulates comprising fruit pit pieces, wood, compositeparticulates, and combinations thereof. Suitable composite particulatesmay comprise a binder and a filler material wherein suitable fillermaterials include silica, alumina, fumed carbon, carbon black, graphite,mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc,zirconia, boron, fly ash, hollow glass microspheres, solid glass, andcombinations thereof. The particulate size generally may range fromabout 2 mesh to about 400 mesh on the U.S. Sieve Series; however, incertain circumstances, other sizes may be desired and will be entirelysuitable for practice of the present invention. In particularembodiments, preferred particulates size distribution ranges are one ormore of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70mesh. It should be understood that the term “particulate,” as used inthis disclosure, includes all known shapes of materials, includingsubstantially spherical materials, fibrous materials, polygonalmaterials (such as cubic materials), and mixtures thereof. Moreover,fibrous materials, that may or may not be used to bear the pressure of aclosed fracture, are often included in fracturing and sand controltreatments. In certain embodiments, the particulates included in thetreatment fluids of the present invention may be coated with anysuitable resin or tackifying agent known to those of ordinary skill inthe art.

The treatment fluids of the present invention may further comprise anadditive for maintaining and/or adjusting pH (e.g., pH buffers, pHadjusting agents, etc.). For example, the additive for maintainingand/or adjusting pH may be included in the treatment fluid so as tomaintain the pH in, or adjust the pH to, a desired range and therebymaintain, or provide, the necessary ionic strength to form the desiredmicellar structures. Examples of suitable additives for maintainingand/or adjusting pH include, but are not limited to, sodium acetate,acetic acid, sodium carbonate, potassium carbonate, sodium bicarbonate,potassium bicarbonate, sodium or potassium diacetate, sodium orpotassium phosphate, sodium or potassium hydrogen phosphate, sodium orpotassium dihydrogen phosphate, sodium hydroxide, potassium hydroxide,lithium hydroxide, combinations thereof, derivatives thereof, and thelike. The additive for adjusting and/or maintaining pH may be present inthe treatment fluids of the present invention in an amount sufficient tomaintain and/or adjust the pH of the fluid. One of ordinary skill in theart, with the benefit of this disclosure, will recognize the appropriateadditive for maintaining and/or adjusting pH and amount thereof to usefor a chosen application.

The treatment fluids of the present invention may optionally compriseadditional additives, including, but not limited to, acids, fluid losscontrol additives, gas, corrosion inhibitors, scale inhibitors,catalysts, clay control agents, biocides, friction reducers,combinations thereof and the like. For example, in some embodiments, itmay be desired to foam a treatment fluid of the present invention usinga gas, such as air, nitrogen, or carbon dioxide. In another embodiment,it may be desired to include an acid in the treatment fluid. It has beendetermined that inclusion of hydrochloric acid in amounts greater thanabout 15% by weight of the aqueous base fluid may impactviscosification. In one certain embodiment, the treatment fluids of thepresent invention may contain a particulate additive, such as aparticulate scale inhibitor. Individuals skilled in the art, with thebenefit of this disclosure, will recognize the types of additives thatmay be necessary for inclusion in the treatment fluids of the presentinvention for a particular application.

The treatment fluids of the present invention may be prepared by anysuitable method. In some embodiments, the treatment fluids may beprepared on the job site. As an example of such an on-site method, a MESsurfactant may be combined with an aqueous base fluid and one or moresalts. As previously mentioned, the one or more salts should providesufficient ionic strength to promote the desired micelle formation, suchthat the treatment fluid exhibits viscoelastic behavior. In someembodiments, the one or more salts may be combined with the aqueous basefluid prior to their combination with the MES surfactant. In one certainembodiment, an additive for adjusting and/or maintaining pH may becombined with the aqueous base fluid, among other things, to provide ormaintain a desired ionic strength. The additive for maintaining and/oradjusting pH may be combined with the aqueous base fluid either priorto, after, or simultaneously with the MES surfactant. Furthermore,additional additives, as discussed above, may be combined with thetreatment fluid and/or the aqueous base fluid as desired. For example, aparticulate additive (e.g., a particulate scale inhibitor) orparticulates (e.g., gravel particulates or proppant particulates) may besuspended in the treatment fluid. In some embodiments, to facilitatemixing with the aqueous base fluid, the MES surfactant may be combinedwith a surfactant solubilizer prior to its combination with the othercomponents of the treatment fluid. The surfactant solubilizer may be anysuitable surfactant solubilizer, such as water, simple alcohols, andcombinations thereof. For example, in some embodiments, the MESsurfactant may be provided in a mixture that comprises the surfactantsolubilizer and the MES surfactant. One or ordinary skill in the art,with the benefit of this disclosure, will be able to determine othersuitable methods for preparation of the treatment fluids.

As previously discussed, at certain conditions, the surfactant moleculespresent in the treatment fluids may associate to form the desiredmicelles, which, depending on a number of factors (e.g., MES surfactantconcentration), may viscosify the fluid so that it exhibits viscoelasticbehavior. The micelles present in the treatment fluids of the presentinvention are generally sensitive to, among other things, the ionicstrength of the fluid, hydrocarbons, and shear stress. Further, theyalso may be sensitive to temperature. Accordingly, these treatmentfluids containing the desired micelles may experience a viscositydecline after introduction into the well bore and/or penetration intothe subterranean formation, without the need for external gel breakers.As previously discussed, this viscosity reduction is generally due tothe dissociation and/or modification of the micellar structure. Forexample, in hydrocarbon-containing portions of the subterraneanformation, the viscosity of the treatment fluids may be reduced bycontact with the hydrocarbons contained therein. Likewise, in certainportions of the subterranean formation (e.g., carbonate formations), thetreatment fluids may experience a pH change, thereby facilitating achange in the ionic strength of the fluid. In certain embodiments,dilution of the treatment fluid may also facilitate a reduction inviscosity of the treatment fluid. For example, the treatment fluid maybe diluted by contact with formation fluids and/or subsequently injectedtreatment fluids, thereby reducing the concentration of the desiredmicelles in the treatment fluid and/or changing the ionic strength ofthe treatment fluid.

The treatment fluids may be used for carrying out a variety ofsubterranean treatments, where a viscosified treatment fluid may beused, including, but not limited to, drilling operations, fracturingtreatments, and completion operations (e.g., gravel packing). In someembodiments, the treatment fluids of the present invention may be usedin treating a portion of a subterranean formation. In certainembodiments, a treatment fluid that comprises an aqueous base fluid, awater-soluble salt, and a MES surfactant may be introduced into a wellbore that penetrates the subterranean formation. In some instances, thetreatment fluid exhibits viscoelastic behavior which may be due, atleast in part, to the association of at least a portion of the MESsurfactant into a plurality of micellar structures. Optionally, thetreatment fluid further may comprise particulates and other additivessuitable for treating the subterranean formation. As previouslymentioned, the treatment fluid generally may experience a reduction inviscosity after placement into the well bore. For example, the treatmentfluid may be allowed to contact the subterranean formation for a periodof time sufficient to reduce the viscosity of the treatment fluid. Insome embodiments, the treatment fluid may be allowed to contacthydrocarbons, formations fluids, and/or subsequently injected treatmentfluids, thereby reducing the viscosity of the treatment fluid. After achosen time, the treatment fluid may be recovered through the well bore.

In certain embodiments, the treatment fluids may be used in fracturingtreatments. In the fracturing embodiments, a treatment fluid thatcomprises an aqueous base fluid, a water-soluble salt, and a MESsurfactant may be introduced into a well bore that penetrates asubterranean formation at or above a pressure sufficient to create orenhance one or more fractures in a portion of the subterraneanformation. Generally, in the fracturing embodiments, the treatment fluidmay exhibit viscoelastic behavior which may be due, at least in part, tothe association of at least a portion of the MES surfactant into aplurality of micellar structures. Optionally, the treatment fluidfurther may comprise particulates and other additives suitable for thefracturing treatment. As previously mentioned, the treatment fluidgenerally may experience a reduction in viscosity after introductioninto the subterranean formation. After a chosen time, the treatmentfluid may be recovered through the well bore.

In certain embodiments, the treatment fluids of the present inventionmay be used for providing some degree of sand control in a portion ofthe subterranean formation. In the sand control embodiments, a treatmentfluid that comprises an aqueous base fluid, a water-soluble salt,particulates, and a MES surfactant may be introduced into a well borethat penetrates the subterranean formation such that the particulatesform a gravel pack in or adjacent to a portion of the subterraneanformation. Generally, in the sand control embodiments, the treatmentfluid may exhibit viscoelastic behavior which may be due, at least inpart, to the association of at least a portion of the MES surfactantinto a plurality of micellar structures. Optionally, the treatment fluidfurther may comprise other additives suitable for the sand controltreatment. In some embodiments, the portion in which some degree of sandcontrol is provided is the same portion of the subterranean formation asthe portion that the gravel pack is formed in or adjacent to. Aspreviously mentioned, the treatment fluid generally may experience areduction in viscosity after introduction into the well bore.Furthermore, any portion of the treatment fluid that leaks off into theformation during the sand control treatment may also experience areduction in viscosity. After a chosen time, the treatment fluid may berecovered from the well bore.

In certain embodiments, the treatment fluids may be used for removingformation particulates from a well bore or from the near well boreregion. These formation particulates may be present in the well bore ofthe near well bore region for a number of reasons, including instanceswhere the formation particulates are generated during the course ofdrilling, digging, blasting, dredging, tunneling, and the like in thesubterranean formation. For example, the treatment fluid may be used asa drilling fluid that is introduced into the well bore, among otherthings, to remove drill cuttings from the well bore. In these formationparticulate removal embodiments, a treatment fluid that comprises anaqueous base fluid, a water-soluble salt, and a MES surfactant isintroduced into the well bore. Generally, the treatment fluid mayexhibit viscoelastic behavior which may be due, at least in part, to theassociation of at least a portion of the MES surfactant into a pluralityof micellar structures. The treatment fluid should be introduced intothe well bore so that it suspends a plurality of formation particulatesin the well bore or in the near well bore region. In these embodiments,the treatment fluid should be recovered from the well bore before theviscosity thereof is substantially reduced so that the treatment fluidhas sufficient viscosity to transport the formation particulates out ofthe well bore. In some embodiments, after recovery from the well bore,the viscosity of the treatment fluid may be reduced, inter alia, so asto facilitate separation of the formation particulates therefrom.

To facilitate a better understanding of the present invention, thefollowing examples of preferred embodiments are given. In no way shouldthe following examples be read to limit, or define, the scope of theinvention.

EXAMPLES Example 1

To determine the viscosification of a treatment fluid using a MESsurfactant, laboratory samples were prepared by mixing a MES surfactant(EFS™-4 surfactant) with an aqueous base fluid. The aqueous base fluidused was tap water unless otherwise indicated. In certain samples, asalt was included in the aqueous base fluid. Where included, theconcentration and type of salt included in the aqueous base fluid werevaried. Once prepared, each sample was observed to determine gelformation. For purposes of this example, a sample was considered gelledif it had a viscosity of greater than about 20 centipoise at 511 sec⁻¹.The compositions of each sample and observations thereof are listed inTable 1. TABLE 1 MES Concentration¹ Sample No. (by weight) Aqueous BaseFluid Result 1 5% Water Not gelled 2 5% Seawater Gelled 3 5% 5% KCl bywt Gelled 4 5% 5% NaCl by wt Gelled 5 5% 10% NaCl by wt Gelled 6 5% 5%CaCl₂ by wt Gelled 7 5% 10% CaCl₂ by wt Gelled 8 5% 5% NaCl by wt Gelled5% CaCl₂ by wt 9 5% 10% NaCl by wt Gelled 10% CaCl₂ by wt 10 5% 5% NH₄Clby wt Gelled 11 5% 10% NH₄Cl by wt Gelled¹Similar results were obtained for each sample when 10% by weight of theMES surfactant was used.

Additionally, further samples were prepared, wherein a sufficient amountof sodium hydroxide was included in the aqueous base fluid so that thepH of the sample was above 7, i.e., the sample was basified. In certainsamples, a salt was included in the aqueous base fluid. Where included,the concentration and type of salt included in the aqueous base fluidwere varied. Once prepared, each sample was observed to determine thegel formation. The compositions of each sample and observations thereofare listed in Table 2. TABLE 2 MES Aqueous Base Fluid Concentration²(basified with NaOH Sample No. (by weight) to pH 10) Result 12 5% 5%NaCl by wt Gelled 13 5% 10% NaCl by wt Gelled 5% KCl by wt 14 5% 5%CaCl₂ by wt Gelled 15 5% 10% CaCl₂ by wt Gelled 16 5% 5% NaCl by wtGelled 5% CaCl₂ by wt 17 5% 10% NaCl by wt Gelled 10% CaCl₂ by wt 18 5%seawater Gelled 19 5% 5% NH₄Cl by wt Gelled²Similar results were obtained for each sample when 10% by weight of theMES surfactant was used.

Additionally, further samples were prepared, wherein a sufficient amountof hydrochloric acid was included in the aqueous base fluid so that thepH of the sample was below 7, i.e., the sample was acidified. In certainsamples, a salt was included in the aqueous base fluid. Where included,the concentration and type of salt included in the aqueous base fluidwere varied. Once prepared, each sample was observed to determine thegel formation. The compositions of each sample and observations thereofare listed in Table 3. TABLE 3 MES Aqueous Base Fluid Concentration³(acidified with HCl Sample No. (by weight) to pH 4) Result 20 5% 5% NaClby wt Gelled 21 5% 10% NaCl by wt Gelled 5% KCl by wt 22 5% 5% CaCl₂ bywt Gelled 23 5% 10% CaCl₂ by wt Gelled 24 5% 5% NaCl by wt Gelled 5%CaCl₂ by wt 25 5% 10% NaCl by wt Gelled 10% CaCl₂ by wt 26 5% seawaterGelled 27 5% 5% NH₄Cl by wt Gelled³Similar results were obtained for each sample when 10% by weight of theMES surfactant was used.

Additionally, further samples were prepared wherein the aqueous basefluid contained 15% hydrochloric acid by weight of the aqueous basefluid. In certain samples, a salt was included in the aqueous basefluid. Where included, the concentration and type of salt included inthe aqueous base fluid were varied. Once prepared, each sample wasobserved to determine the gel formation. The compositions of each sampleand observations thereof are listed in Table 4. TABLE 4 MESConcentration⁴ Sample No. (by weight) Aqueous Base Fluid Result 28 5%15% HCl Not gelled 29 5% 15% HCl Not gelled 5% NaCl by wt 30 5% 15% HClNot gelled 5% KCl by wt 31 5% 15% HCl Not gelled 5% CaCl₂ by wt 32 5%15% HCl Not gelled 5% NH₄Cl by wt⁴Similar results were obtained for each sample when 10% by weight of theMES surfactant was used.

Additionally, further samples were prepared wherein the aqueous basefluid contained 10% hydrochloric acid by weight of the aqueous basefluid. In certain samples, a salt was included in the aqueous basefluid. Where included, the concentration and type of salt included inthe aqueous base fluid were varied. Once prepared, each sample wasobserved to determine the gel formation. The compositions of each sampleand observations thereof are listed in Table 5. TABLE 5 MESConcentration Sample No. (by weight) Aqueous Base Fluid Result 33 5% 10%HCl Gelled 34 5% 10% HCl Gelled 5% NaCl by wt 35 5% 10% HCl Gelled 5%KCl by wt 36 5% 10% HCl Gelled 5% CaCl₂ by wt 37 5% 10% HCl Gelled 5%NH₄Cl by wt

Additionally, further samples were prepared, wherein a sufficient amountof sodium hydroxide was included in the aqueous base fluid so that thepH of the sample was above 7, i.e., the sample was basified. In certainsamples, a salt was included in the aqueous base fluid. Where included,the concentration and type of salt included in the aqueous base fluidwere varied. Once prepared, each sample was observed to determine thegel formation. The compositions of each sample and observations thereofare listed in Table 6. TABLE 6 MES Aqueous Base Fluid Concentration(basified with Sample No. (by weight) NaOH to pH 10) Result 38 5% 5%CaCl₂ by wt Gelled 39 5% 5% MgCl₂ by wt Gelled 40 5% 5% CaCl₂ by wtGelled 5% MgCl₂ by wt

Additionally, further samples were prepared, wherein a sufficient amountof hydrochloric acid was included in the aqueous base fluid so that thepH of the sample was below 7, i.e., the sample was acidified. In certainsamples, a salt was included in the aqueous base fluid. Where included,the concentration and type of salt included in the aqueous base fluidwere varied. Once prepared, each sample was observed to determine thegel formation. The compositions of each sample and observations thereofare listed in Table 7. TABLE 7 MES Aqueous Base Fluid Concentration(acidified with HCl Sample No. (by weight) to pH 4) Result 41 5% 5%CaCl₂ by wt Gelled 42 5% 5% MgCl₂ by wt Gelled 43 5% 5% CaCl₂ by wtGelled 5% MgCl₂ by wt

Thus, Example 1 indicates that a MES surfactant may be used to viscosifya fluid.

Example 2

Rheological tests were performed on laboratory samples that wereprepared as follows. Samples were prepared by mixing water with thefollowing components: an MES surfactant in an amount of about 1.5% byweight of the sample; a cocobetaine in an amount of about 1.5% by weightof the sample component; and various concentrations of sodium chloride(3.5%, 4.0%, 4.5%, 6.0%, and 7.0%). The MES surfactant included in thesamples was an alpha-sulfo fatty acid methyl ester that is commerciallyavailable as ALPHA-STEP XMP-66® from Stepan Company, Northfield, Ill.Further, the cocobetaine used in the samples is commercially availableas Witco Rewoteric AM B-13®.

Once prepared, the samples were each placed in the R1 rotor cup of aFann Model 50 viscometer to determine the viscosities of the sample,utilizing a nonscanning shear rate procedure. The rotor cups containingthe samples were set in motion at a constant rate of about 95 rpmproviding a shear rate of about 82 sec⁻¹ on the sample. The sample wasbrought up to about 230° F. as the viscosities of the samples weremeasured. A plot of temperature (° F.) versus viscosity (cP) for eachsample is provided in FIG. 1. Table 8 identifies the maximum viscositiesand corresponding temperatures for each sample. TABLE 8 NaClConcentration Max Viscosity Temperature (by weight) (cP) (° F.) 3.5% 73133 4.0% 88 132 4.5% 97 132 6.0% 98 142 7.0% 92 141

Thus, Example 2 illustrates that a MES surfactant may be used toviscosify a fluid.

Example 3

Rheological tests were performed on laboratory samples that wereprepared as follows. Two samples were prepared by mixing water with thefollowing components: an MES surfactant in an amount of about 5% byweight of the sample with about 5% sodium chloride. Sample A was usedwithout adjusting the pH. The pH of Sample B was adjusted with NaOH toabout 10. The MES surfactant included in the samples was an alpha-sulfofatty acid methyl ester that is commercially available as EFS™-4Surfactant from Halliburton Energy Services, Inc., Duncan, Okla.

Once the samples were prepared, the rheology was determined using aHaake RheoStress RS150 stress-controlled rheometer fitted with a 60 mmdiameter, 2° cone and plate. The temperature was held constant at 25° C.A constant frequency (1 Hz) oscillatory stress sweep was performed overthe stress range indicated to obtain the storage modulus (G′), lossmodulus (G″), and phase angle (δ). Results are shown in FIGS. 2 and 3for Samples A and B, respectively.

Thus, Example 3 illustrates that a MES surfactant may be used toviscosify a fluid.

Therefore, the present invention is well adapted to carry out theobjects and attain the ends and advantages mentioned as well as thosewhich are inherent therein. While numerous changes may be made by thoseskilled in the art, such changes are encompassed within the spirit ofthis invention as defined by the appended claims. The terms in theclaims have their plain, ordinary meaning unless otherwise defined bythe patentee.

1. A method of treating a subterranean formation, the method comprising:providing a treatment fluid comprising: an aqueous base fluid; awater-soluble salt; and a methyl ester sulfonate surfactant having thefollowing formula:

where R is an alkyl chain of about 10 carbon atoms to about 30 carbonatoms; and introducing the treatment fluid into a well bore thatpenetrates the subterranean formation.
 2. The method of claim 1 whereinthe treatment fluid exhibits viscoelastic behavior due, at least inpart, to the association of at least a portion of the methyl estersulfonate surfactant into a plurality of micellar structures.
 3. Themethod of claim 1 wherein the water-soluble salt comprises at least oneof the following: ammonium chloride; lithium bromide; lithium chloride;lithium formate; lithium nitrate; calcium bromide; calcium chloride;calcium nitrate; calcium formate; sodium bromide; sodium chloride;sodium formate; sodium nitrate; potassium chloride; potassium bromide;potassium nitrate; potassium formate; cesium nitrate; cesium formate;cesium chloride; cesium bromide; magnesium chloride; magnesium bromide;zinc chloride; zinc bromide; or a derivative thereof.
 4. The method ofclaim 1 wherein the methyl ester sulfonate surfactant is present in thetreatment fluid in an amount of from about 0.5% to about 15% by weightof the treatment fluid.
 5. The method of claim 1 wherein R is an alkylchain of from about 16 carbon atoms to about 22 carbon atoms.
 6. Themethod of claim 1 wherein the treatment fluid further comprises at leastone of the following: particulates; a co-surfactant; an additive foradjusting and/or maintaining pH; an acid; a fluid loss control additive;a gas; a corrosion inhibitor; a scale inhibitor; a catalyst; a claycontrol agent; a biocide; or a friction reducer.
 7. The method of claim6 wherein the particulates comprise at least one of the following: sand;bauxite; ceramic materials; glass materials; polymer materials;Teflon®materials; nut shell pieces; cured resinous particulatescomprising nut shell pieces; seed shell pieces; cured resinousparticulates comprising seed shell pieces; fruit pit pieces; curedresinous particulates comprising fruit pit pieces; wood; or compositeparticulates.
 8. The method of claim 6 wherein the particulates arecoated with a resin or a tackifying agent.
 9. The method of claim 6wherein the co-surfactant comprises at least one of the following: abetaine; an amine oxide; or a derivative thereof.
 10. The method ofclaim 6 wherein the co-surfactant is present in the treatment fluid in aco-surfactant-to-methyl ester sulfonate surfactant weight ratio in therange of from about 1:3 to about 3:1.
 11. The method of claim 1 furthercomprising allowing the treatment fluid to contact the subterraneanformation for a period of time sufficient to reduce the viscosity of thetreatment fluid.
 12. The method of claim 1 further comprising allowingthe treatment fluid to contact hydrocarbons contained in thesubterranean formation, a formation fluid, and/or a treatment fluid,thereby reducing the viscosity of the treatment fluid.
 13. The method ofclaim 1 further comprising recovering the treatment fluid through thewell bore.
 14. A method of fracturing a subterranean formation, themethod comprising: providing a treatment fluid, the treatment fluidcomprising: an aqueous base fluid; a water-soluble salt; and a methylester sulfonate surfactant having the following formula:

where R is an alkyl chain of about 10 carbon atoms to about 30 carbonatoms, wherein the treatment fluid exhibits viscoelastic behavior due,at least in part, to the association of at least a portion of the methylester sulfonate surfactant into a plurality of micellar structures; andintroducing the treatment fluid into a well bore that penetrates thesubterranean formation at or above a pressure sufficient to create orenhance one or more fractures in a portion of the subterraneanformation.
 15. The method of claim 14 further comprising allowing thetreatment fluid to contact hydrocarbons contained in the subterraneanformation, a formation fluid, and/or a treatment fluid, thereby reducingthe viscosity of the treatment fluid.
 16. The method of claim 14 furthercomprising allowing the treatment fluid to contact the subterraneanformation for a period of time sufficient to reduce the viscosity of thetreatment fluid.
 17. The method of claim 14 wherein the treatment fluidfurther comprises at least one of the following: particulates; aco-surfactant; an additive for adjusting and/or maintaining pH; an acid;a fluid loss control additive; a gas; a corrosion inhibitor; a scaleinhibitor; a catalyst; a clay control agent; a biocide; or a frictionreducer.
 18. A method of removing formation particulates from a wellbore or a near well bore region, the method comprising: providing atreatment fluid, the treatment fluid comprising: an aqueous base fluid;a water-soluble salt; and a methyl ester sulfonate surfactant having thefollowing formula:

where R is an alkyl chain of about 10 carbon atoms to about 30 carbonatoms, wherein the treatment fluid exhibits viscoelastic behavior due,at least in part, to the association of at least a portion of the methylester sulfonate surfactant into a plurality of micellar structures; andintroducing the treatment fluid into the well bore so as to suspend aplurality of formation particulates in the treatment fluid.
 19. Themethod of claim 18 wherein the formation particulates comprise drillcuttings.
 20. The method of claim 18 wherein the treatment fluid furthercomprises at least one of the following: particulates; a co-surfactant;an additive for adjusting and/or maintaining pH; an acid; a fluid losscontrol additive; a gas; a corrosion inhibitor; a scale inhibitor; acatalyst; a clay control agent; a biocide; or a friction reducer.